1. Field of the Invention
This invention relates generally to rotary drill bits used in drilling subterranean wells and, more specifically, to drill bits having a gage definition portion or region that relatively gradually expands the diameter of the wellbore from that cut by the face cutters to substantially the full gage diameter of the bit.
2. State of the Art
The equipment used in drilling operations is well known in the art and generally comprises a drill bit attached to a drill string, including drill pipe and drill collars. A rotary table or other device such as a top drive is used to rotate the drill string, resulting in a corresponding rotation of the drill bit. The drill collars, which are heavier per unit length than drill pipe, are normally used on the bottom part of the drill string to add weight to the drill bit, increasing weight on bit (WOB). The weight of these drill collars presses the drill bit against the formation at the bottom of the borehole, causing it to drill when rotated. Downhole motors are also sometimes employed, in which case the bit is secured to the output or drive shaft of the motor.
A typical rotary drill bit includes a bit body, with a connecting structure for connecting the bit body to the drill string, such as a threaded portion on a shank extending from the bit body, and a crown comprising that part of the bit fitted with cutting structures for cutting into an earth formation. Generally, if the bit is a fixed-cutter or so-called "drag" bit, the cutting structures include a series of cutting elements made of a superabrasive material, such as polycrystalline diamond, oriented on the bit face at an angle to the surface being cut (i.e., side rake, back rake).
Various manufacturing techniques known in the art are utilized for making such a drill bit. In general, the bit body may typically be formed from a cast or machined steel mass or a tungsten carbide matrix cast by infiltration with a liquified metal binder onto a blank which is welded to a tubular shank. Threads are then formed onto the free end of the shank to correspondingly match the threads of a drill collar.
Cutting elements are usually secured to the bit by preliminary bonding to a carrier element, such as a stud, post or elongated cylinder, which in turn is inserted into a pocket, socket or other aperture in the crown of the bit and mechanically or metallurgically secured thereto. Specifically, polycrystalline diamond compact (PDC) cutting elements, usually of a circular or disc-shape comprising a diamond table bonded to a supporting WC substrate, may be brazed to a matrix-type bit after furnacing. Alternatively, freestanding (unsupported) metal-coated thermally stable PDCs (commonly termed TSPs) may be bonded into the bit body during the furnacing process used to fabricate a matrix-type drill bit.
A TSP may be formed by leaching out the metal in the diamond table. Such TSPs are suitable for the aforementioned metal coatings, which provide a metallurgical bond between the matrix binder and the diamond mass. Alternatively, silicon, which possesses a coefficient of thermal expansion similar to that of diamond, may be used to bond diamond particles to produce an Si-bonded TSP which, however, is not susceptible to metal coating. TSPs are capable of enduring higher temperatures (on the order of 1200.degree. C.) used in furnacing matrix-type bits without degradation in comparison to normal PDCs, which experience thermal degradation upon exposure to temperatures of about 750-800.degree. C.
The direction of the loading applied to the radially outermost (gage) cutters is primarily lateral. Such loading is thus tangential in nature, as opposed to the force on the cutters on the face of the bit which is substantially provided by the WOB and thus comprises a normal force substantially in alignment with the longitudinal bit axis. The tangential forces tend to unduly stress even cutters specifically designed to accommodate this type of loading and high bounce rates, due to the relatively large depths of cut taken by cutters employed to define the gage of the borehole and the stress concentrations experienced by the relatively small number of cutters assigned the task of cutting the gage diameter. It should be realized that, for any given rotational speed of a bit, the cutters proximate the gage area of the bit are traveling at the highest velocities of any cutters on the bit due to their location at the largest radii. Such cutters also traverse the longest distances during operation of the bit. Therefore, their velocity plus their distance traveled, and the large sideways or lateral resistive loads encountered by the cutters, which loads may be equivalent to those at the center of the bit face, may overwhelm even the most robust, state-of-the-art superabrasive cutters. While the radially outermost cutting elements on the bit face, referred to as gage cutters, typically have a flattened or linear radially outer profile aligned parallel to the longitudinal axis of the bit to reduce cutter exposure and cut a precise gage diameter through the borehole, such profiles actually enhance or speed up wear due to the large contact areas, which generate excessive heat. Wear of the gage cutters may, over time, result in an undergage wellbore.
In a typical bit arrangement, the gage of the bit is that substantially cylindrical portion located adjacent to and extending above the gage cutters longitudinally along the bit body at a given radius from the bit centerline. In a slick gage arrangement, such as that shown in U.S. Pat. No. 5,178,222, the radius of the gage is essentially the same as the outer diameter defined by the gage cutters.
During drilling as the bit penetrates into a formation, a typical slick gage drill bit will drill the borehole diameter with the gage cutters, the gage of the bit then snugly passing therethrough. Even when the gage cutters extend a substantial radial distance beyond the gage of the bit from the bit centerline, as the gage cutters wear and the diameter of the wellbore consequently decreases to become closer to that of the bit gage, greater frictional resistance by the gage against the wall of the wellbore will be experienced. As a result, the rate of penetration (ROP) of the drill bit will continually decrease, requiring more WOB until the gage cutters may degrade to a point where the ROP is unacceptable. At that point, the worn bit must be tripped out of the borehole and replaced with a new one, even though the face cutting structure may be relatively unworn.
One way known in the art to lengthen the life of the drill bit is to provide cutting elements on the gage of the bit. For example, U.S. Pat. No. 5,467,836 discloses a drill bit having gage inserts that provide an active cutting gage surface that engages the sidewall of the borehole to promote shearing removal of the sidewall material. U.S. Pat. No. 5,004,057 illustrates a drill bit having both an upper and lower gage section having gage cutting portions located thereon. Other prior art bits include both abrasion resistant pads and cutters on the gage of the bit, such as the bit disclosed in U.S. Pat. No. 5,163,524.
The bits disclosed in the aforementioned references, however, do not provide a gage definition region that relatively, gradually and incrementally expands the diameter of the wellbore from that cut by the face of the bit to the gage diameter. Thus, it would be advantageous to provide variously configured definitional cutting regions having cutting structures arranged thereon to maintain the ROP and/or accommodate various ROPs of the drill bit through a formation and reduce the loads applied to any one cutter whether in the region or at the definitional gage diameter of the bit.
Cutting elements of a fixed-cutter drill bit have typically been arranged along the lower edges of longitudinally extending blades, each cutting element being positioned at a different radial location relative to the longitudinal axis of the bit. An exemplary arrangement of cutting elements is illustrated in U.S. Pat. No. 5,178,222 to Jones et al. and assigned to the assignee of the present invention. In FIG. 4 of the patent, all the cutting elements of the bit are shown, illustrating their horizontal overlapping paths upon rotation of the bit. Upon one complete rotation of the bit, it has been believed, by having the cutting elements arranged in such an overlapping configuration, a substantially uniform layer of material from the bottom of the wellbore can be removed, the thickness of the layer and the rotational speed of the bit determining the ROP.
While other blade orientations have been considered, including spiral blades such as those found on the drill bit illustrated in U.S. Pat. No. 4,848,489 to Deane, the cutting elements of such a bit have been arranged with regard to substantially the same horizontal plane (i.e., perpendicular to the longitudinal axis of the bit) and thus to horizontally overlap upon rotation of the drill bit. In sum, prior art bits have been designed in a two-dimensional framework with cutting elements positioned and oriented to cut the formation upon rotation of the bit without consideration of the effects of the vertical movement of the bit into the formation. Additionally, this two-dimensional framework has resulted in gage cutters being spaced and positioned in a similar manner to cutters on the bit face.
U.S. Pat. No. 5,314,033 to Tibbitts, herein incorporated by reference and assigned to the assignee of the present invention, recognized that the path of each cutting element on a drill bit follows a helical path into the formation and that the angle of the helical path affects the effective rake angle of the cutter. Accordingly, the cutting elements were attached to the face of the bit at various back rake angles, depending on their position on the bit face, taking into account their effective rake angle, and cooperatively associated with at least one other cutter to enhance the cooperative cutting of the cutting elements.
Recognizing that the path of the cutting elements into the formation is helical in nature, the aforementioned patent teaches how this helical path affects the actual or effective rake angle of the cutting elements. Such path also, however, affects the loading of each cutting element, depending on the cutter's position relative to the longitudinal axis of the bit. Thus, it would be desirable to provide a drill bit having cutting elements in the outer radius area of the bit body arranged to effectively reduce the stresses experienced by each cutting element at or near the gage diameter of the bit by incrementally cutting the outermost portion of the wellbore to full gage diameter using a relatively large number of cutters, each taking a small depth of cut. Such a drill bit would result in longer cutting element life by reducing individual wear and decreasing the rate of cutter failure and/or wear in the gage region of the bit.